Multilateral access with real-time data transmission

ABSTRACT

An example method includes introducing a downhole tool string into a main wellbore of a multilateral wellbore that includes a lateral wellbore that extends from the main wellbore. The downhole tool string includes a wand and a kickover knuckle joint coupled to the wand. A first measurement is obtained with an orientation measurement device, and an angular orientation of the kickover knuckle joint and the wand is aligned with the lateral wellbore as based on the first measurement. The downhole tool string is then advanced into the lateral wellbore and a second measurement is obtained with the orientation measurement device within the lateral wellbore. The second measurement is compared with known deviation survey measurements corresponding to the lateral wellbore to verifying a location of the downhole tool string in the lateral wellbore. A wellbore stimulation operation is then undertaken with the downhole tool string within the lateral wellbore.

BACKGROUND

The present disclosure relates to multilateral wellbore operations and,more particularly, to downhole tool strings having an orientationmeasurement device that can be used to locate lateral wellbores.

Operators seeking to produce hydrocarbons from subterranean formationsoften drill multilateral wells. Unlike conventional vertical wells, amultilateral well includes a primary wellbore and one or more lateralwellbores that branch from the primary wellbore. Although multilateralwells are often more expensive to drill and complete than conventionalwells, multilateral wells are generally more cost-effective overall, asthey usually maximize production of reservoirs and therefore havegreater production capacity and higher recoverable reserves.Multilateral wells are also an attractive choice in situations where itis necessary or desirable to reduce the amount of surface drillingoperations, such as when environmental regulations impose drillingrestrictions.

Although multilateral wells may offer advantages over conventionalwells, they may also involve greater complexity, which may poseadditional challenges. One such challenge involves locating and enteringa specific lateral wellbore that branches from a primary wellbore. Anumber of techniques have been developed for locating and enteringlateral wellbores, including the installation of special jewelry in thecasing at a junction of the lateral and primary wellbores. This jewelryallows the landing of a whipstock adjacent to the junction to force anysubsequent tubing run into the primary wellbore into the desired lateralwellbore.

Another technique for locating and entering a lateral wellbore involvesutilizing a downhole tool string that includes an indexing tool, akickover knuckle joint attached to the lower end of the indexing tool,and a wand extension attached to the lower end of the kickover knucklejoint. The downhole tool string may first be lowered to the bottom ofthe primary wellbore to tag the bottom thereof and perform any desiredtreatment. After performing the treatment, the downhole tool string maythen be raised to the estimated location of a junction between theprimary and lateral wellbores. The kickover knuckle joint can be used todeflect the wand away from the central axis of the downhole tool stringand fluid is pumped to the downhole tool string from a surface location,which will maintain the wand in contact with the wellbore, preventing itfrom fully kicking out. Upon locating the lateral wellbore, the tip ofthe wand is able to bend fully into the lateral wellbore and exhaustpressurized fluid from the downhole tool string, which may be sensed atthe surface as a pressure drop, and thereby provide positive indicationthat the lateral wellbore has been located.

If the wand fails to locate the lateral wellbore, the downhole toolstring is lowered again a certain amount of length in the primarywellbore and the indexing tool may be used to rotate the kickoverknuckle joint and the wand to operate at a different angularorientation. The downhole tool string is then raised within the primarywellbore until the wand locates the lateral wellbore. This process isrepeated until the wand positively locates the lateral wellbore.

As can be appreciated, this process can require a significantconsumption of fluids needed to operate the downhole tool string throughthese repetitions, which can occur over the span of potentially severalhours, as well as excessively fatiguing the coiled tubing workstring.

Moreover, in some cases, fluid venting from the downhole tool string maynot reliably signal that a lateral wellbore has been located. In someinstances, for example, the tip of the wand may not fully bend and venteven though it locates and enters a lateral wellbore. In other cases,the downhole tool string may vent when it is not in the lateralwellbore, inter a/ia, because the curvature of the conveyance (e.g.,coiled tubing) above the downhole tool string may be sufficient to allowthe wand to fully bend and vent. Because of the possibility of prematureventing, once the operator believes that a lateral wellbore has beenpositively located, the downhole tool string is often lowered to thebottom of the lateral wellbore to tag the bottom thereof. This depth isthen compared with the previously recorded depth of the primary wellboreand, if the two depths are identical, it can be surmised that a lateralwellbore has not been found, and the operator must repeat the procedurefor locating the lateral wellbore.

The need to repeatedly tag the bottom of the primary and lateralwellbores may add undesirable delays and expense to lateral wellboreoperations. Lateral wellbores that have a very similar bottom depth alsopose an additional problem, as it might not be clear on which of the twolaterals the coiled tubing and string are located.

BRIEF DESCRIPTION OF THE DRAWINGS

The following figures are included to illustrate certain aspects of thepresent disclosure, and should not be viewed as exclusive embodiments.The subject matter disclosed is capable of considerable modifications,alterations, combinations, and equivalents in form and function, withoutdeparting from the scope of this disclosure.

FIG. 1 depicts a rigless well intervention system in which theprinciples of the present disclosure may be employed.

FIGS. 2A and 2B are progressive partial cross-sectional views of anexemplary downhole tool string.

FIG. 3 is a schematic flow chart of a method of locating a lateralwellbore.

DETAILED DESCRIPTION

The present disclosure relates to multilateral wellbore operations and,more particularly, to a downhole tool strings having an orientationmeasurement device that can be used to locate lateral wellbores.

The embodiments described herein provide a system and method of locatinga lateral wellbore of a multilateral wellbore and performing a wellborestimulation in the lateral wellbore. According to the presentdisclosure, a downhole tool string includes an orientation measurementdevice that can provide real-time measurements of inclination, azimuth,and tool face direction as the downhole tool string advances downhole.The real-time measurements may be used to angularly align a wandincluded in the downhole tool string with the lateral wellbore, andsubsequently verify that the downhole tool string has positively enteredthe lateral wellbore. This may prove advantageous in eliminating theneed to pump excessive amounts of fluid to the downhole tool string andthe wand in seeking the lateral wellbore, and may also reduce the timerequired to find the lateral wellbore. Moreover, the downhole toolstring and associated conveyance may assume less fatigue since multiplecycling up and down within the wellbore can be avoided by implementingthe principles of the present disclosure. Once the downhole tool hassuccessfully entered the lateral wellbore, a wellbore stimulationoperation such as acidizing, water conformance treatments, distributedtemperature survey with fiber optics, abrasive perforating, amongstothers.

Referring to FIG. 1, illustrated is an exemplary rigless wellintervention system 100 that may employ the principles of the presentdisclosure, according to one or more embodiments. As illustrated, therigless well intervention system 100 (hereafter “the system 100”) mayinclude a parent or main wellbore 102 and at least one lateral wellbore104 that extends from the main wellbore 102. The main wellbore 102 maybe a wellbore drilled from a surface location (not shown) to penetrate asubterranean formation 106, and the lateral wellbore 104 may intersectthe main wellbore 102 at a junction 108 and may otherwise comprise alateral or deviated wellbore drilled at an angle from the main wellbore102. While the main wellbore 102 is shown as being oriented generallyvertical, the main wellbore 102 may alternatively be oriented generallyhorizontal or at any angle between vertical and horizontal, withoutdeparting from the scope of the disclosure.

Both the main and lateral wellbores 102, 104 may be lined with a lineror a string of casing 110 and subsequently cemented in place, or may beleft without any liner, which is called a “barefoot” completion. Asknown in the art, the string of casing 110 may comprise multiple lengthsof tubular conduits or pipe secured together at their ends and extendedinto the main and lateral wellbores 102, 104.

The system 100 may further include a downhole tool string 112 that isable to be run into the main wellbore 102 on a conveyance 114 extendingfrom the surface location (not shown). In some embodiments, theconveyance 114 may be coiled tubing or the like, and the surfacelocation may include a wellhead installation (not shown) and a coiledtubing unit (not shown). The coiled tubing unit may be configured toaccess the main wellbore 102 via the wellhead installation and therebyextend the downhole tool string 112 into the main wellbore 102.Accordingly, in at least one embodiment, the system 100 may becharacterized as “rigless,” meaning that a drilling rig or drillingservice unit is not located nor required at the surface location.Rather, the main and lateral wellbores 102, 104 have already beendrilled and completed, and the downhole tool string 112 may beselectively introduced into the main and/or lateral wellbores 102, 104to undertake one or more wellbore stimulation operations, such asacidizing, water conformance treatments, distributed temperature surveywith fiber optics, abrasive perforating, amongst others.

The downhole tool string 112 may include various components and devicesused to undertake the wellbore stimulation operations. In someembodiments, for instance, the downhole tool string 112 may include atleast an orienting sub 116, an orientation measurement device 118, akickover knuckle joint 120, and a wand 122. In at least one embodiment,the downhole tool string 112 may further include at least onecentralizer (not shown) used to radially centralize the downhole toolstring 112 within the main and/or lateral wellbores 102, 104. Thevarious components of the downhole tool string 112 may be connected toeach other end to end with threaded connections. In all embodiments, thedownhole tool string 112 may facilitate fluid communication through itsentire length and thereby able to provide a fluid to the wand 122 fromthe conveyance 114.

The orienting sub 116 may include any known device used for rotating thecomponents of the downhole tool string 112 about a central axis 124 ofthe downhole tool string 112. More particularly, the orienting sub 116may be selectively activated to rotate the orientation measurementdevice 118, the kickover knuckle joint 120, and the wand 122 about thecentral axis 124. In other embodiments, as described below, the axialpositions of the orienting sub 116 and the orientation measurementdevice 118 may be reversed, without departing from the scope of thedisclosure.

Example devices that may be suitable as the orienting sub 116 include,but are not limited to, an indexing tool and a continuously run motor.An indexing tool may facilitate rotation of a predetermined number ofdegrees (e.g., 30°, 45°, etc.) about the central axis 124 upon actuatingor being activated. The indexing tool may be activated using fluidpressure conveyed thereto via the conveyance 114. When the fluidpressure from the conveyance 114 is increased and subsequently released,the indexing tool may be configured to automatically rotate thepredetermined number of degrees, and thereby alter the angularconfiguration of the components of the downhole tool string 112 locatedtherebelow. In embodiments where the orienting sub 116 is a continuouslyrun motor, the continuously run motor may provide selective 360°rotation about the central axis 124 of the downhole tool string 112. Oneof ordinary skill in the art with the benefit of this disclosure will beable to select and employ an appropriate orienting sub 116 for aparticular application.

The orientation measurement device 118 may include one or more sensorsconfigured to measure, detect, and otherwise determine the orientationof a known fixed point on the downhole tool string 112 relative togravity, magnetic north, or other parsable environmental constants. Insome embodiments, for example, the orientation measurement device 118may comprise a measurement-while-drilling (MWD) tool, such as a MWD toolcommercially available from Sperry Drilling and Halliburton EnergyServices of Houston, Tex., USA. The orientation measurement device 118may be configured to measure and report the real-time azimuth,inclination, and tool-face direction of the downhole tool string 112and, more particularly, of the kickover knuckle joint 120 and the wand122, in addition to temperature and gamma ray measurements.

The orientation measurement device 118 may also include a wellboretelemetry device 126 configured to communicate either wired orwirelessly with the surface location, thereby allowing a well operatorto receive real-time measurements of the azimuth, inclination, andtool-face direction of the downhole tool string 112. The wellboretelemetry device 126 may be any downhole telemetering device known tothose skilled in the art including, but not limited to, mud pulsetelemetry, electromagnetic telemetry, acoustic telemetry, ultrasonictelemetry, electrical lines, fiber optic lines, radio frequencytransmission, or any combination thereof.

The kickover knuckle joint 120 may be any suitable device adapted todeflect the wand 122 with respect to the central axis 124 of thedownhole tool string 112. In some embodiments, the kickover knucklejoint 120 is a selectively activated knuckle joint, such as a hydraulickickover joint available from NOV. Other suitable kickover knucklejoints 120 include, but are not limited to, restricted ball joints, pinjoints, bourdon tubes, or an asymmetrically slotted member with internalpressurization means. One of ordinary skill in the art with the benefitof this disclosure should be able to select and implement theappropriate kickover knuckle joint 120 for a particular application.

In some embodiments, the kickover knuckle joint 120 may not bend ordeflect until it is activated through fluid pressure conveyed theretovia the conveyance 114. Upon assuming fluid pressure, the kickoverknuckle joint may be configured to bend or otherwise deflect from thecentral axis 124. Accordingly, activation of the kickover knuckle joint120 may be controlled from the surface by controlling the hydraulicpressure conveyed to the kickover knuckle joint 120 via the conveyance114.

The wand 122, also known as a nozzle probe, may be operatively coupledto the kickover knuckle joint 120 and otherwise located at the distalend of the downhole tool string 112. By activating the kickover knucklejoint 120, the wand 122 may be deflected from alignment with the centralaxis 124 to enter a lateral wellbore, such as the lateral wellbore 104.

The wand 122 may exhibit a length sufficient to be deflected into thelateral wellbore 104 when it locates the junction 108. The wand 122 maybe deflected with respect to the central axis 124 to a predeterminedmaximum deflection angle 128. The maximum deflection angle 128 of thewand 122 may depend on a number of factors, including the inner diameterof the main wellbore 102 and the axial length of wand 122. Generally, asuitable maximum deflection angle 128 for the wand 122 may be in therange from about 3° to about 30° from the central axis 124. In someembodiments, the kickover knuckle joint 120 may be configured to deflectthe wand 122 about 15° from the central axis 124.

Exemplary operation of the downhole tool string 112 in locating andentering the lateral wellbore 104 is now provided. The general locationof the junction 108 and its angular orientation within the main wellbore102 may be known from prior survey measurements taken while drilling andcompleting the main and lateral wellbores 102, 104. Upon building thedownhole tool string 112, the angular orientation of the kickoverknuckle joint 120 may also be noted and known relative to theorientation measurement device 118. Therefore, using the measurementsobtained by the orientation measurement device 118 as the downhole toolstring 112 is conveyed downhole, the angular orientation of the kickoverknuckle joint 120 within the main wellbore 102 may be calculated andotherwise known. The angular orientation of the kickover knuckle joint120 may be reoriented as needed so that the wand 122 is able toangularly align with the lateral wellbore 104. Changing the angularorientation of the kickover knuckle joint 120 may be accomplished byactivating the orienting sub 116 to rotate the kickover knuckle joint120 and the wand 122 the predetermined number of degrees (e.g., 30°,45°, etc.).

As the downhole tool string 112 is conveyed downhole within the mainwellbore 102, the orientation measurement device 118 may be continuouslyobtaining measurements and reporting the same in real-time to thesurface location using the wellbore telemetry device 126. As a result, awell operator may be apprised of the real-time location of the downholetool string 112 as it nears the junction 108. Upon reaching the junction108, the angular orientation of the wand 122 may be adjusted so that itis able to align with the lateral wellbore 104. The correct angularorientation of the wand 122 may be confirmed in real-time with theorientation measurement device 118 or otherwise as the wand 122 bends ordeflects into the lateral wellbore 104 and vents fluid pressure, whichmay be sensed at the surface location.

Once the wand 122 is angularly oriented with the lateral wellbore 104,the downhole tool string 112 may be advanced into the lateral wellbore104 and the orientation measurement device 118 may again be used toverify the present location of the downhole tool string 112. Moreparticularly, after entering the lateral wellbore 104, the location ofthe downhole tool string 112 may be uniquely validated in real-time byobtaining new inclination, azimuth, and tool-face direction measurementswith the orientation measurement device 118 and comparing thosemeasurements with known deviation survey measurements corresponding tothe lateral wellbore 104. If the new measurements and the deviationsurvey measurements fail to match, that may indicate that the downholetool string 112 failed to enter the lateral wellbore 104 and insteadremains in the main wellbore 102. If this occurs, the lateral locationprocedure will be repeated. If the present measurements and thedeviation survey measurements match, however, that may provide positiveindication that the downhole tool string 112 has successfully enteredthe lateral wellbore 104. While in the lateral wellbore 104, the welloperator may proceed to undertake various wellbore stimulationoperations, such as acidizing, water conformance treatments, distributedtemperature survey with fiber optics, abrasive perforations, amongstothers.

Referring now to FIGS. 2A and 2B, illustrated are progressive partialcross-sectional views of an exemplary downhole tool string 200,according to one or more embodiments. The downhole tool string 200 maybe the same as or similar to the downhole tool string 112 of FIG. 1 andtherefore may be best understood with reference thereto, where likenumerals indicate like components not described again. FIG. 2A depictsan exploded view of the upper portions of the downhole tool string 200,and FIG. 2B depicts an exploded view of the lower portions of thedownhole tool string 200. As indicated by the exploded views, thevarious components of the downhole tool string 200 may be threadablycoupled. In other embodiments, however, one or more of the components ofthe downhole tool string 200 may be coupled using any other attachmentmeans including, but not limited to, mechanical fasteners, welding, andbrazing.

Referring first to FIG. 2A, the downhole tool string 200 may include aconnector 202 used to couple the downhole tool string 200 to aconveyance, such as the conveyance 114 of FIG. 1. The downhole toolstring 200 may further include a motor head assembly 204 and asequencing flow sub 206 positioned between the connector 202 and theorienting sub 116. The motor head assembly 204 may include one or morecheck valves 210 (shown as a first check valve and a second check valve)configured to prevent fluid from flowing uphole and otherwise back tothe conveyance 114 from the downhole tool string 200. Rather, the checkvalves 210 may be configured to allow fluid to proceed downhole throughthe downhole tool string 200.

The motor head assembly 204 may further include a hydraulic disconnect208 a, a circulation port 208 b, and a burst disc 212. The hydraulicdisconnect 208 a may allow lower portions of the downhole tool string200 below the motor head assembly 204 to be disconnected in the eventthe downhole tool string 200 becomes stuck in the main or lateralwellbores 102, 104 (FIG. 1). The circulation port 208 b may provide anoutlet for fluids conveyed to the downhole tool string 200 from theconveyance 114 (FIG. 1) in the event the lower portions of the downholetool string 200 below the motor head assembly 204 become stuck. Theburst disc 212 may allow fluid circulation through the downhole toolstring 200 in the event the lower components of the downhole tool string200 below the motor head assembly 204 become plugged. Penetrating orbreaking the burst disc 212 may result in fluid communication to theannulus surrounding the downhole tool assembly 200 via the motor headassembly 204.

The sequencing flow sub 206 may be activated to divert fluid flowreceived from the conveyance 114 (FIG. 1) so that no fluid flows to thecomponents of the downhole tool string 200 below the sequencing flow sub206. Following its actuation, any fluid introduced into the sequencingflow sub 206 may be diverted and ejected from the sequencing flow sub206 via one or more side nozzles 207. As will be appreciated, thesequencing flow sub 206 may allow stimulation fluids, such as abrasivefluids and acids, to be injected into the main and lateral wellbores102, 104 (FIG. 1) while undertaking the various wellbore stimulationoperations mentioned herein. The mechanism of activation of thesequencing flow sub 206 is based on flow rate of the fluid pumped fromthe surface. The sequencing flow sub 206 can be setup with several flowrate activation settings, depending on the specific need. Once the flowexceeds the predetermined rate, the flow to the tools below thesequencing flow sub 206 is stopped via a spring-operated mechanism orsimilar, and a sleeve, or another similar device, shifts to expose thenozzles 207, thus allowing flow to come out of the nozzles 207.

In some embodiments, a cross-over sub 214 may interpose and otherwise bepositioned between the orienting sub 116 and the orientation measurementdevice 118. In other embodiments, however, the cross-over sub 214 may beomitted and the orienting sub 116 may instead be directly coupled to theorientation measurement device 118, without departing from the scope ofthe disclosure.

Referring to FIG. 2B, in some embodiments, the downhole tool string 200may further include a gauge carrier 216. In at least one embodiment, across-over sub 218 may interpose and otherwise be positioned between thegauge carrier 216 and the orientation measurement device 118 (FIG. 2A).In other embodiments, however, the cross-over sub 218 may be omitted andthe gauge carrier 216 may instead be directly coupled to the orientationmeasurement device 118, without departing from the scope of thedisclosure.

The gauge carrier 216 may include various sensors and gauges used tomeasure downhole parameters such as, but not limited to, pressure andtemperature. The sensors and gauges included in the gauge carrier 216may further include a gamma ray sensor and a casing collar locator.

As illustrated, an optional cross-over sub 220 may interpose andotherwise be positioned between the gauge carrier 216 and the kickoverknuckle joint 120. Moreover, in some embodiments, the downhole toolstring 200 may further include an extension arm 222 used to extend thereach or axial length of the wand 122 located at the distal end of thedownhole tool string 200. As will be appreciated, the extension arm 222may prove advantageous in embodiments where the diameter of the main orlateral wellbores 102, 104 (FIG. 1) are large. In other embodiments, theextension arm 222 may be omitted. As illustrated in FIG. 2B, the wand122 may include one or more vents 224 (shown as vents 224 a and 224 b)defined therein. The vents 224 a,b may provide outlets used to ventfluid pressure from the downhole tool string 220 when the wand 122locates and deflects into a lateral wellbore (e.g., the lateral wellbore104 of FIG. 2).

In the illustrated embodiment of FIGS. 2A and 2B, the orientationmeasurement device 118 is depicted as being positioned below theorienting sub 116 along the axial length of the downhole tool string 200and thereby able to obtain real-time inclination and tool-face datacloser to the kickover knuckle joint 120. In other embodiments, however,the orientation measurement device 118 may alternatively be positionedabove the orienting sub 116, without departing from the scope of thedisclosure. In such embodiments, the angular orientation of the kickoverknuckle joint 120 may nonetheless be known or otherwise calculated byknowing the degrees of rotation per indexing cycle of the orienting sub116 and the number of times the orienting sub 116 has been activated.

Referring now to FIG. 3, illustrated is a schematic flow chart of anexemplary method 300 of locating a lateral wellbore, according to one ormore embodiments. The method 300 may be accomplished using either of thedownhole tool strings 112, 200 described herein in locating and enteringone or more lateral wellbores, such as the lateral wellbore 104 ofFIG. 1. According to the method 300, a downhole tool string may beintroduced into a main wellbore of a multilateral wellbore, as at 302.The multilateral wellbore may include a lateral wellbore that extendsfrom the main wellbore at a junction. Moreover, the downhole tool stringmay include a wand and a kickover knuckle joint coupled to the wand.

A first measurement may be obtained with an orientation measurementdevice included in the downhole tool string, as at 304. The firstmeasurement may include at least one of an azimuth, an inclination, anda tool-face direction of the downhole tool string. The first measurementmay be communicated to a surface location in real time with a wellboretelemetry device communicably coupled to the orientation measurementdevice. The angular orientation of the kickover knuckle joint and thewand may then be aligned with the lateral wellbore as based on the firstmeasurement, as at 306. In some embodiments, this may include activatingan orienting sub included in the downhole tool string, and therebychanging the angular orientation of the kickover knuckle joint and thewand.

The downhole tool string may then be advanced into the lateral wellboreto obtain a second measurement with the orientation measurement device,as at 308. The second measurement may be obtained while the downholetool string is positioned in the lateral wellbore and may include atleast one of the azimuth, the inclination, and the tool-face directionof the downhole tool string. The second measurement may be communicatedto the surface location in real time with the wellbore telemetry device.

The second measurement may then be compared with known deviation surveymeasurements corresponding to the lateral wellbore, as at 310. Comparingthe second measurement with the known deviation survey measurements mayverify a location of the downhole tool string within the lateralwellbore. Once it is verified that the downhole tool string is locatedwithin the lateral wellbore, one or more wellbore stimulation operationsmay be undertaken with the downhole tool string while positioned in thelateral wellbore, as at 312. Undertaking the one or more wellborestimulation operations may include activating a sequencing flow subincluded in the downhole tool string to prevent a stimulation fluid frompassing into at least an orienting sub, the kickover knuckle joint, andthe wand, and diverting the stimulation fluid out of the sequencing flowsub. Undertaking the one or more wellbore stimulation operations mayfurther include at least one treating a portion of the lateral wellboresuch as acidizing, water conformance treatments, distributed temperaturesurvey with fiber optics, abrasive perforating, amongst others. Theforegoing steps of 302-312 may then be repeated at a second lateralwellbore within the multilateral wellbore, as at 314.

Embodiments disclosed herein include:

A. A method that includes introducing a downhole tool string into a mainwellbore of a multilateral wellbore, the multilateral wellbore includinga lateral wellbore that extends from the main wellbore at a junction,and the downhole tool string including a wand and a kickover knucklejoint coupled to the wand, obtaining a first measurement with anorientation measurement device included in the downhole tool string, thefirst measurement including at least one of an azimuth, an inclination,and a tool-face direction of the downhole tool string, aligning anangular orientation of the kickover knuckle joint and the wand with thelateral wellbore as based on the first measurement, advancing thedownhole tool string into the lateral wellbore and obtaining a secondmeasurement with the orientation measurement device while the downholetool string is positioned in the lateral wellbore, the secondmeasurement including at least one of the azimuth, the inclination, andthe tool-face direction of the downhole tool string, comparing thesecond measurement with known deviation survey measurementscorresponding to the lateral wellbore and thereby verifying a locationof the downhole tool string in the lateral wellbore, and undertaking oneor more wellbore stimulation operations with the downhole tool stringwhile positioned in the lateral wellbore.

B. A rigless well intervention system that includes a main wellborehaving at least a portion thereof lined with casing, a lateral wellborethat extends from the main wellbore at a junction, at least a portion ofthe lateral wellbore being lined with casing, a downhole tool stringextendable within the main wellbore on a conveyance from a surfacelocation and having a central axis, the downhole tool string including awand and a kickover knuckle joint coupled to the wand to deflect thewand from the central axis, an orienting sub that adjusts an angularorientation of at least the kickover knuckle joint and the wand aboutthe central axis, an orientation measurement device that measures one ormore of an azimuth, an inclination, and a tool-face direction of atleast one of the kickover knuckle joint and the wand, a wellboretelemetry device communicably coupled to the orientation measurementdevice for communicating at least one of the azimuth, the inclination,and the tool-face direction to the surface location in real-time, and asequencing flow sub that is actuatable to prevent a stimulation fluidfrom passing into at least the orienting sub, the kickover knucklejoint, and the wand, and instead divert the stimulation fluid out of thesequencing flow sub to undertake a wellbore stimulation operation in thelateral wellbore.

C. A downhole tool string that includes a wand, a kickover knuckle jointcoupled to the wand to deflect the wand from a central axis, anorienting sub that adjusts an angular orientation of at least thekickover knuckle joint and the wand about the central axis, anorientation measurement device that measures one or more of an azimuth,an inclination, and a tool-face direction of at least one of thekickover knuckle joint and the wand, a wellbore telemetry devicecommunicably coupled to the orientation measurement device forcommunicating at least one of the azimuth, the inclination, and thetool-face direction to a surface location in real-time, and a sequencingflow sub that is actuatable to prevent a stimulation fluid from passinginto at least the orienting sub, the kickover knuckle joint, and thewand, and instead divert the stimulation fluid out of the sequencingflow sub to undertake a wellbore stimulation operation.

Each of embodiments A, B, and C may have one or more of the followingadditional elements in any combination: Element 1: wherein aligning theangular orientation of the kickover knuckle joint and the wand with thelateral wellbore comprises activating an orienting sub included in thedownhole tool string, and changing the angular orientation of thekickover knuckle joint and the wand with the orienting sub. Element 2:wherein the downhole tool string further includes a sequencing flow sub,and wherein undertaking the one or more wellbore stimulation operationscomprises activating the sequencing flow sub to prevent a stimulationfluid from passing into at least an orienting sub, the kickover knucklejoint, and the wand, and diverting the stimulation fluid out of thesequencing flow sub. Element 3: wherein undertaking the one or morewellbore stimulation operations comprises at least one of acidizing aportion of the lateral wellbore and hydraulically fracturing a portionof the lateral wellbore. Element 4: wherein the downhole tool stringfurther includes a wellbore telemetry device communicably coupled to theorientation measurement device, the method further comprisingcommunicating the first and second measurements to the surface locationin real-time. Element 5: wherein communicating the first and secondmeasurements to the surface location in real-time comprises operatingthe wellbore isolation device using at least one of mud pulse telemetry,electromagnetic telemetry, acoustic telemetry, ultrasonic telemetry,electrical lines, fiber optic lines, radio frequency transmission, andany combination thereof. Element 6: wherein the downhole tool stringfurther includes a gauge carrier that includes one or more sensors orgauges, the method further comprising measuring one or more downholeparameters with the gauge carrier as the downhole tool string advanceswithin the main or lateral wellbores. Element 7: wherein the lateralwellbore is a first lateral wellbore and the junction is a firstjunction, the method further comprising retracting the downhole toolstring from the first lateral wellbore and into the main wellbore,moving the downhole tool string within the main wellbore toward a secondlateral wellbore that extends from the main wellbore at a secondjunction, obtaining a third measurement with the orientation measurementdevice, the first measurement including at least one of the azimuth, theinclination, and the tool-face direction of the downhole tool string,aligning the angular orientation of the kickover knuckle joint and thewand with the second lateral wellbore as based on the third measurement,advancing the downhole tool string into the second lateral wellbore andobtaining a fourth measurement with the orientation measurement devicewhile the downhole tool string is positioned in the second lateralwellbore, the fourth measurement including at least one of the azimuth,the inclination, and the tool-face direction of the downhole toolstring, comparing the fourth measurement with known deviation surveymeasurements corresponding to the second lateral wellbore and therebyverifying a location of the downhole tool string in the second lateralwellbore, and undertaking one or more wellbore stimulation operationswith the downhole tool string while positioned in the second lateralwellbore. Element 8: wherein undertaking the one or more wellborestimulation operations with the downhole tool string while positioned inthe second lateral wellbore comprises at least one of acidizing aportion of the second lateral wellbore and hydraulically fracturing aportion of the second lateral wellbore.

Element 9: wherein the conveyance is coiled tubing. Element 10: whereinthe orienting sub is an indexing tool that rotates a predeterminednumber of degrees about the central axis upon being activated. Element11: wherein the orientation measurement device comprises ameasurement-while-drilling tool. Element 12: wherein the wellboretelemetry device operates using at least one of mud pulse telemetry,electromagnetic telemetry, acoustic telemetry, ultrasonic telemetry,electrical lines, fiber optic lines, radio frequency transmission, andany combination thereof. Element 13: wherein the stimulation fluid is atleast one of a fracturing fluid and an acid.

Element 14: wherein the orienting sub is an indexing tool that rotates apredetermined number of degrees about the central axis upon beingactivated. Element 15: wherein the orientation measurement devicecomprises a measurement-while-drilling tool. Element 16: wherein thewellbore telemetry device operates using at least one of mud pulsetelemetry, electromagnetic telemetry, acoustic telemetry, ultrasonictelemetry, an electrical line, a fiber optic line, radio frequencytransmission, and any combination thereof. Element 17: wherein thestimulation fluid is at least one of a fracturing fluid and an acid.Element 18: further comprising a motor head assembly, and a gaugecarrier that includes one or more sensors or gauges used to measuredownhole parameters.

By way of non-limiting example, exemplary combinations applicable to A,B, and C include: Element 4 with Element 5; Element 7 with Element 8;Element 9 with Element 11; and Element 9 with Element 12.

Therefore, the disclosed systems and methods are well adapted to attainthe ends and advantages mentioned as well as those that are inherenttherein. The particular embodiments disclosed above are illustrativeonly, as the teachings of the present disclosure may be modified andpracticed in different but equivalent manners apparent to those skilledin the art having the benefit of the teachings herein. Furthermore, nolimitations are intended to the details of construction or design hereinshown, other than as described in the claims below. It is thereforeevident that the particular illustrative embodiments disclosed above maybe altered, combined, or modified and all such variations are consideredwithin the scope of the present disclosure. The systems and methodsillustratively disclosed herein may suitably be practiced in the absenceof any element that is not specifically disclosed herein and/or anyoptional element disclosed herein. While compositions and methods aredescribed in terms of “comprising,” “containing,” or “including” variouscomponents or steps, the compositions and methods can also “consistessentially of” or “consist of” the various components and steps. Allnumbers and ranges disclosed above may vary by some amount. Whenever anumerical range with a lower limit and an upper limit is disclosed, anynumber and any included range falling within the range is specificallydisclosed. In particular, every range of values (of the form, “fromabout a to about b,” or, equivalently, “from approximately a to b,” or,equivalently, “from approximately a-b”) disclosed herein is to beunderstood to set forth every number and range encompassed within thebroader range of values. Also, the terms in the claims have their plain,ordinary meaning unless otherwise explicitly and clearly defined by thepatentee. Moreover, the indefinite articles “a” or “an,” as used in theclaims, are defined herein to mean one or more than one of the elementthat it introduces. If there is any conflict in the usages of a word orterm in this specification and one or more patent or other documentsthat may be incorporated herein by reference, the definitions that areconsistent with this specification should be adopted.

As used herein, the phrase “at least one of” preceding a series ofitems, with the terms “and” or “or” to separate any of the items,modifies the list as a whole, rather than each member of the list (i.e.,each item). The phrase “at least one of” allows a meaning that includesat least one of any one of the items, and/or at least one of anycombination of the items, and/or at least one of each of the items. Byway of example, the phrases “at least one of A, B, and C” or “at leastone of A, B, or C” each refer to only A, only B, or only C; anycombination of A, B, and C; and/or at least one of each of A, B, and C.

The use of directional terms such as above, below, upper, lower, upward,downward, left, right, uphole, downhole and the like are used inrelation to the illustrative embodiments as they are depicted in thefigures, the upward direction being toward the top of the correspondingfigure and the downward direction being toward the bottom of thecorresponding figure, the uphole direction being toward the surface ofthe well and the downhole direction being toward the toe of the well.

What is claimed is:
 1. A method, comprising: introducing a downhole toolstring into a main wellbore of a multilateral wellbore, the multilateralwellbore including a lateral wellbore that extends from the mainwellbore at a junction, and the downhole tool string including a wandand a kickover knuckle joint coupled to the wand; obtaining a firstmeasurement with an orientation measurement device included in thedownhole tool string, the first measurement including at least one ofthe following measurements: an azimuth, an inclination, and a tool-facedirection of the downhole tool string; aligning an angular orientationof the kickover knuckle joint and the wand with the lateral wellbore asbased on the first measurement; advancing the downhole tool string intothe lateral wellbore and obtaining a second measurement with theorientation measurement device while the downhole tool string ispositioned in the lateral wellbore, the second measurement including atleast one of the azimuth, the inclination, and the tool-face directionof the downhole tool string; and comparing the second measurement withknown deviation survey measurements corresponding to the lateralwellbore and thereby verifying a location of the downhole tool string inthe lateral wellbore; and undertaking one or more wellbore stimulationoperations with the downhole tool string while positioned in the lateralwellbore.
 2. The method of claim 1, wherein aligning the angularorientation of the kickover knuckle joint and the wand with the lateralwellbore comprises: activating an orienting sub included in the downholetool string; and changing the angular orientation of the kickoverknuckle joint and the wand with the orienting sub.
 3. The method ofclaim 1, wherein the downhole tool string further includes a sequencingflow sub, and wherein undertaking the one or more wellbore stimulationoperations comprises: activating the sequencing flow sub to prevent astimulation fluid from passing into at least an orienting sub, thekickover knuckle joint, and the wand; and diverting the stimulationfluid out of the sequencing flow sub.
 4. The method of claim 1, whereinundertaking the one or more wellbore stimulation operations comprises atleast one of acidizing a portion of the lateral wellbore andhydraulically fracturing a portion of the lateral wellbore.
 5. Themethod of claim 1, wherein the downhole tool string further includes awellbore telemetry device communicably coupled to the orientationmeasurement device, the method further comprising communicating thefirst and second measurements to the surface location in real-time. 6.The method of claim 5, wherein communicating the first and secondmeasurements to the surface location in real-time comprises operatingthe wellbore isolation device using at least one of mud pulse telemetry,electromagnetic telemetry, acoustic telemetry, ultrasonic telemetry,electrical lines, fiber optic lines, radio frequency transmission, andany combination thereof.
 7. The method of claim 1, wherein the downholetool string further includes a gauge carrier that includes one or moresensors or gauges, the method further comprising measuring one or moredownhole parameters with the gauge carrier as the downhole tool stringadvances within the main or lateral wellbores.
 8. The method of claim 1,wherein the lateral wellbore is a first lateral wellbore and thejunction is a first junction, the method further comprising: retractingthe downhole tool string from the first lateral wellbore and into themain wellbore; moving the downhole tool string within the main wellboretoward a second lateral wellbore that extends from the main wellbore ata second junction; obtaining a third measurement with the orientationmeasurement device, the first measurement including at least one of theazimuth, the inclination, and the tool-face direction of the downholetool string; aligning the angular orientation of the kickover knucklejoint and the wand with the second lateral wellbore as based on thethird measurement; advancing the downhole tool string into the secondlateral wellbore and obtaining a fourth measurement with the orientationmeasurement device while the downhole tool string is positioned in thesecond lateral wellbore, the fourth measurement including at least oneof the azimuth, the inclination, and the tool-face direction of thedownhole tool string; comparing the fourth measurement with knowndeviation survey measurements corresponding to the second lateralwellbore and thereby verifying a location of the downhole tool string inthe second lateral wellbore; and undertaking one or more wellborestimulation operations with the downhole tool string while positioned inthe second lateral wellbore.
 9. The method of claim 8, whereinundertaking the one or more wellbore stimulation operations with thedownhole tool string while positioned in the second lateral wellborecomprises at least one of acidizing a portion of the second lateralwellbore and hydraulically fracturing a portion of the second lateralwellbore.
 10. A rigless well intervention system, comprising: a downholetool string extendable within a main wellbore on a conveyance from asurface location, the main wellbore having a central axis and a lateralwellbore that extends from the main wellbore at a junction, wherein atleast a portion of each of the main and lateral wellbores is lined withcasing, the downhole tool string including: a wand and a kickoverknuckle joint coupled to the wand to deflect the wand from the centralaxis; an orienting sub that adjusts an angular orientation of at leastthe kickover knuckle joint and the wand about the central axis; anorientation measurement device that measures one or more of an azimuth,an inclination, and a tool-face direction of at least one of thekickover knuckle joint and the wand; a wellbore telemetry devicecommunicably coupled to the orientation measurement device forcommunicating at least one of the azimuth, the inclination, and thetool-face direction to the surface location in real-time; and asequencing flow sub that is actuatable to prevent a stimulation fluidfrom passing into at least the orienting sub, the kickover knucklejoint, and the wand, and instead divert the stimulation fluid out of thesequencing flow sub to undertake a wellbore stimulation operation in thelateral wellbore.
 11. The system of claim 10, wherein the conveyance iscoiled tubing.
 12. The system of claim 10, wherein the orienting sub isan indexing tool that rotates a predetermined number of degrees aboutthe central axis upon being activated.
 13. The system of claim 10,wherein the orientation measurement device comprises ameasurement-while-drilling tool.
 14. The system of claim 10, wherein thewellbore telemetry device operates using at least one of mud pulsetelemetry, electromagnetic telemetry, acoustic telemetry, ultrasonictelemetry, electrical lines, fiber optic lines, radio frequencytransmission, and any combination thereof.
 15. The system of claim 10,wherein the stimulation fluid is at least one of a fracturing fluid andan acid.
 16. A downhole tool string, comprising: a wand; a kickoverknuckle joint coupled to the wand to deflect the wand from a centralaxis; an orienting sub that adjusts an angular orientation of at leastthe kickover knuckle joint and the wand about the central axis; anorientation measurement device that measures one or more of an azimuth,an inclination, and a tool-face direction of at least one of thekickover knuckle joint and the wand; a wellbore telemetry devicecommunicably coupled to the orientation measurement device forcommunicating at least one of the azimuth, the inclination, and thetool-face direction to a surface location in real-time; and a sequencingflow sub that is actuatable to prevent a stimulation fluid from passinginto at least the orienting sub, the kickover knuckle joint, and thewand, and instead divert the stimulation fluid out of the sequencingflow sub to undertake a wellbore stimulation operation.
 17. The downholetool string of claim 16, wherein the orienting sub is an indexing toolthat rotates a predetermined number of degrees about the central axisupon being activated.
 18. The downhole tool string of claim 16, whereinthe orientation measurement device comprises ameasurement-while-drilling tool.
 19. The downhole tool string of claim16, wherein the wellbore telemetry device operates using at least one ofmud pulse telemetry, electromagnetic telemetry, acoustic telemetry,ultrasonic telemetry, an electrical line, a fiber optic line, radiofrequency transmission, and any combination thereof.
 20. The downholetool string of claim 16, wherein the stimulation fluid is at least oneof a fracturing fluid and an acid.
 21. The downhole tool string of claim16, further comprising: a motor head assembly; and a gauge carrier thatincludes one or more sensors or gauges used to measure downholeparameters.